The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface, a drill string extending from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. The system relies on a drilling mud which is pumped through the inside of the drill string, cools and lubricates the drill bit and then exists out of the drill bit and carries the rock cuttings back to surface. The mud also helps control bottom hole pressure and prevents hydrocarbon influx from the formation into the wellbore and potential blow out at surface.
Directional drilling is the process of steering a well from vertical to intersect a target endpoint or follow a prescribed path. At the terminal end of the drill string, is a bottom-hole-assembly (or BHA) which comprises 1) a drill bit; 2) a steerable downhole mud motor of rotary steerable system; 3) sensors of survey equipment Logging While Drilling (LWD) and/or Measurement-while-drilling (MWD) to evaluate downhole conditions as well depth progresses; 4) means for transmitting telemetry data to surface; and 5) other control processes such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore typically within a metallic tubular. The mud motor has a drive shaft that uses the drilling fluid passing through it to rotate the bit (rather than the surface rig spinning the entire drill string as in conventional drilling of vertical wells.). The outer housing of the mud motor has a bend in it which can be oriented to push or deflect the drill bit in a desired direction, allowing the driller to steer the well. Measurement While Drilling (MWD) equipment is used to provide downhole sensor and status information to surface while drilling in a near real-time mode. This information is used by the rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, hydrocarbon size and location, etc. This can include making intentional deviations from the planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real time data measurements while drilling allows for a relatively more economical and more efficient drilling operation.
Downhole MWD tools typically contain similar sensor packages to survey the well bore and surrounding formation, but can feature a number of different telemetry transmitting means. Such telemetry means include acoustic telemetry, fibre optic cable, mud pulse (MP) telemetry and electromagnetic (EM) telemetry.
MP telemetry involves creating pressure waves in the circulating drill mud in the drill string. Information acquired by the downhole sensors is transmitted in specific time divisions by creating a series of pressure waves in the mud column. This is achieved by changing the flow area and/or path of the drilling fluid as it passes the MWD tool in a timed, coded sequence, thereby creating pressure differentials in the drilling fluid. The pressure differentials or pulses may either be negative pulse or positive pulses in nature. The pulses travel to surface to be decoded by transducers in the surface piping, reconstructing the data sent from the downhole sensor package. One or more signal processing techniques are used to separate undesired mud pump noise, rig noise or downward propagating noise from upward (MWD) signals. The data transmission rate is governed by acoustic waves in a drilling mud and is typically about 1.1 to 1.5 km/s.
EM telemetry involves the generation of electromagnetic waves which travel through the earth's surrounding formations from the wellbore, with detection of the waves at surface. In EM telemetry systems, a very low frequency alternating current is driven across a gap sub, which is typically part of the BHA. The gap sub comprises an electrically isolated (‘nonconductive”), effectively creating an insulating break (“gap”) between the bottom of the drill string to the drill bit, and the longer top portion that includes the rest of the drill pipe up to the surface. The lower part of the drill string below the gap typically is set as a ground but the polarity of the members can be switched. An EM telemetry signal comprising a low frequency AC voltage is controlled in a timed/coded sequence to energize the earth and create a measurable voltage differential between the surface ground and the top of the drill string. The EM signal which originated across the gap is detected at surface and measured as a difference in the electric potential from the drill rig to various surface grounding rods located about the lease site.
MP and EM telemetry systems each have their respective strengths and weaknesses. For instance, MP telemetry systems tend to provide good depth capability, independence on earth formation, and current strong market acceptance. However, MP telemetry systems tend to provide generally slower baud rates and more narrow bandwidths compared to EM telemetry, and require mud to be flowing in order for telemetry to be transmitted. Thus, MP telemetry systems are incompatible with air/underbalanced drilling, which is a growing market in North America.
In contrast, EM telemetry systems generally provide faster baud rates and increased reliability due to no moving downhole parts compared to MP telemetry systems, high resistance to lost circulating material (LCM) use, and are suitable for air/underbalanced drilling. Unlike MP telemetry systems, EM telemetry systems transmit data through the earth formation and not through a continuous fluid column; hence EM telemetry can be transmitted when there is no mud flowing through the drill string. However, EM telemetry systems can be incompatible with some formations such as formations containing high salt content or formations of high resistivity contrast. Also, EM transmissions can be strongly attenuated over long distances through the earth formations, with higher frequency signals attenuating faster than low frequency signals, and thus EM telemetry tends to require a relatively large amount of power and/or utilize relatively low frequencies so that the signals can be detected at surface. These limitations create challenges with battery life and lowered data rate transmission in the downhole MWD tool.
Recently, combined telemetry systems including both EM and MP telemetry means have been proposed. However, such known combined telemetry systems are relatively underdeveloped, and for instance, often simply stack a known EM tool and a known MP tool in series with minimal system integration. Such known combined telemetry systems also do not feature sophisticated data management between the EM and MP telemetry tools, and thus are not optimized for performance, reliability, and efficient power consumption.